1. Field of the Invention
This invention relates to chemical corrosion inhibitors which have demonstrated utility in the control of acid gas corrosion and especially acid gas corrosion resulting from carbon dioxide in the absense of oxygen. The invention also relates to the method for preparing the corrosion inhibitors and to their use in gas conditioning services.
2. The Prior Art
The corrosion inhibitors of this invention have utility in any gas stream that contains carbon dioxide. Although functional in acid gas streams containing carbon dioxide and oxygen the preferred application is in acid gas streams which are substantially oxygen free. The presence of carbon dioxide and resulting necessity for its stripping by gas treatment services, i.e. monoethanolamine, inherently results in a corrosion problem. The corrosion problem is typically attacked by use of chemical corrosion inhibitors. The gas streams for which the corrosion inhibitor of this invention are necessary are created from a number of sources including flue gas from power plants, natural gas from wellheads and petroleum refineries. The source of gas is not limiting on the use of this invention.
One of the most common mechanisms for the stripping of carbon dioxide from gases is monoethanolamine (sometimes referred to as "MEA"). The use of MEA in the treatment of acid gases is described in a paper ("Contamination and Corrosion in Monoethanolamine Gas Treating Solutions"--Report #722, B. G. Hofmeyer, H. G. Scholten, W. G. Lloyd of the Dow Chemical Company) presented before the Dec. 1, 1955 meeting of the Petroleum Section of The American Chemical Society in Dallas, Texas. Although MEA is only one of several known chemicals for the treatment of acid gases, the thiourea-amine-formaldehyde corrosion inhibitor of this invention has shown exceptional utility in combination with MEA used at concentrations of greater than 15% by weight.
In petroleum refining operations, a distillation procedure is used to separate various fractions from the petroleum crude. The recovered fractions are cooled, condensed, and sent to collecting equipment. No matter what the source of oil that is subject to distillation it has been found that corrosion of the equipment takes place. Acidic materials that are present in all crudes are carried along from the distillation zone with the distillate product and often cause extensive corrosion to take place on the metal surfaces of fractionating towers such as crude towers, trays within such towers, heat exchangers, receiving tanks, connecting pipes, etc.
The most serious corrosion occurs in condensers and in the overhead line leading from the fractionating towers. The overhead line is used as a connection between the distillation tower and condensers. The distillate or stock which will be stored or used subsequently to charge other refining processes is condensed on the cooling surfaces of the condenser equipment and is then caught in an overhead accumulator drum. A portion of the distillate is recycled to the crude pot with the remainder being transferred to other refinery units. Refineries are but one example of areas where corrosion inhibitors are essential.
The conditioning of gases, both natural and synthetic, i.e., acid gas stripping, and the removal of acid gases, e.g., CO.sub.2, H.sub.2 S and COS, by absorption of the acidic gases in a liquid absorbent medium, has been practiced for many years. Various absorbents, such as the alkanolamines, "sulfolane" (tetrahydrothiophene-1, 1-dioxide), "sulfinol" (tetrahydrothiophene-1, 1-dioxide+diisopropanolamine), potassium carbonate and the like have been used commercially.
Each of the commercial gas conditioning systems is plagued by corrosion problems, some of which result from decomposition of the absorbent, some from reaction between the acidic components of the gases treated and the absorbent, and all, to more or less the same degree, from attack by the acidic components of the gases treated upon the metals of construction of the equipment. Generally, the corrosion occurs in the regenerator, heat exchangers, pumps and piping associated with these elements of the overall equipment.
Numerous compounds have been suggested as additives to the absorbents to prevent the corrosion and/or deformation of corrosive elements. For example, copper sulfate was used for three years in a 15% monoethanol amine gas processing plant for removing 10% carbon dioxide from the gas. Corrosion was observed as a decrease in reboiler and heat exchange tube life and on analysis of the amine solution, only a few parts per million copper was found, thus indicating excessive copper deposition in the unit. (Gas Conditioning Fact Book, The Dow Chemical Co., Midland, Mich., 1962, pp. 157-158, Case No. 8).
Each of these chemicals and others which are available in the prior art address the problem of general corrosion. General corrosion is electrochemical in nature. Corrosion is a familiar term and generally is understood to represent the gradual wearing away by chemical or electrochemical means of metal. Although corrosion is typically understood to result when metal, especially ferrous metals, are maintained in prolonged contact with water, it is generally understood that corrosion can occur upon contact of metals with any liquid. For purposes of this application corrosion shall be generally understood to include reference to a uniform thinning and loss of metal not accompanied by localized action such as pitting, cracking, or erosion which results from direct chemical reaction or combination such as that which occurs where metal is corroded in gases or by electrochemical action like that which occurs with metals and alloys corroding in liquids. For additional information on corrosion in general reference is made to R. Perry, C. Chilton and S. Kirkpatrick, Chemical Engineers Handbook, 4th ed., Ch. 23 (1963).
A common problem encountered in steel equipment used for handling solutions containing hydrogen sulfide (H.sub.2 S) is hydrogen blistering and cracking. Hydrogen blistering and cracking is a form of corrosion which is generated by the presence of atomic hydrogen. Atomic hydrogen is changed to molecular hydrogen which can penetrate steel. The penetration of steel by the atomic hydrogen results in increased corrosion and increased corrosion rates. Where the problem is recognized as hydrogen blistering and cracking amine type inhibitors have typically been found effective in preventing corrosion. This problem is especially acute in petroleum distillation equipment made out of steel and steel alloys.
Corrosion is a universally recognized phenomenon which is inherent in the use of steel and steel alloys especially ferrous containing steel alloys. The corrosion phenomenon has been the basis for a great deal of research to define methods, procedures and chemicals to control corrosion. Factors which have been shown to effect the occurrence and rate of corrosion include: temperature, velocity, pH, oxidizing and reducing conditions and moisture.
Temperature has been shown to have a dramatic effect on corrosion and especially on the rate of corrosion. As reaction kinetics would predict, practice has shown that corrosion and corrosion rates are higher at higher temperatures. The increase in corrosion and corrosion rates at higher temperatures is especially pronounced in an acid environment. For purposes of this application the temperature range in which the corrosion inhibiting composition will be expected to function is from ambient temperatures to 150.degree. C.
The velocity of the liquid, gas or solution which causes corrosion in the distillation column or other metal structure is directly related to the rate of corrosion. Practice has shown that the higher the velocity the higher the corrosion and rate of corrosion. It is theorized that increased velocity may be responsible for the removal of protective films or scale or simply provide a greater supply of corroding media.
Although the pH of a specific solution which includes corrosion causing media is an important factor in determining corrosion and corrosion rates it is a very complex factor. Ideally, the solution should be at a neutral pH. This would result in the minimum rate of corrosion. However, deviations from neutral to either the acidic (lower) or alkaline (higher) pHs will inevitably result in increased rates of corrosion. As a general rule, a decrease in pH value will result in an increase in the corrosion and corrosion rates of metals subject to corrosion in dilute acid solutions while an increase in pH value above neutral range will result in an increase in corrosion and corrosion rates of metals subject to attack in alkaline solutions.
Moisture is a critical factor in determining corrosion and corrosion rates. The effects of moisture are especially dramatic when its presence results in a change from anhydrous conditions and acidic components are formed by hydrolysis. The presence of moisture is also important in gaseous systems since its presence can cause condensation and present the opportunity for severe corrosion. In general, the occurrence or presence of moisture in an environment will cause an increase in corrosion compared with a moisture free condition.
Finally, the general oxidizing and reducing conditions present in the environment can have a severe effect on corrosion and corrosion rates. In particular, it is noted by practitioners that the chemical and electrochemical nature of the corrosion reaction results in reaction kinetics which are favorably affected by an environment presenting oxidation and reduction conditions.
Although corrosion has been recognized as a problem in the design of steel and other ferrous metals the attempts to eliminate or control corrosion have been varied. The methods of attacking corrosion in the prior art have included: selecting specific materials for specific applications, attempts to use design criteria to minimize corrosion, attempts to alter the environment to provide corrosion resistant conditions, the use of cathotic protection devices, the use of various coatings and linings which are resistant to corrosion, and finally the use of chemical inhibitors. While under proper circumstances each of the prior art methods is effective to a degree it has been the use of chemical corrosion inhibitors which has been the preferred method for controlling corrosion.
Corrosion inhibitors in general are effective as a result of their control over the influence on the cathode or anode area reactions which form the basis for the electrochemical corrosion reaction. In particular, the chemical inhibitors are designed to control corrosion reaction kinetics and to minimize same. Organic sulfide and amine materials are frequently effective in minimizing corrosion of iron and steel in an acid solution.
Patents which have been identified as relevant to the corrosion inhibitor composition of this invention are U.S. Pat. Nos. 3,959,170; 4,100,099; 4,372,873; and 4,440,731.
U.S. Pat. No. 3,959,170 discloses corrosion inhibitor composition for steel equipment used in alkanol amine gas treating systems having antimony and vanadium, compounds or benzotriazole. The disclosure teaches that corrosion can be inhibited by combinations of antimony and vanadium compounds, stannous salts, organo-tin compounds, nitroaromatic acids and their salts or benzotriazole.
U.S. Pat. No. 4,100,099 discloses a corrosion inhibitor composition which is used on iron and steel equipment in sour gas conditioning processes which use aqueous alkanol amine solutions having quaternary pyridinum salts and a lower alkylene polyamine. The disclosure states that aqueous alkanol amine materials are highly corrosive when dissolved sour gases are present and especially when the solution is hot. The patent recites various metal compounds as having been used to combat this problem and specifically lists arsenic, antimony and vanadium.
U.S. Pat. No. 4,372,873 discloses a corrosion inhibitor composition which is used on iron and steel equipment in sour gas conditioning processes using aqueous alkanol amine solutions having a combination of vanadium containing ion and a di- or tri- amine. The disclosure lists a number of vanadium compounds while the amine coinhibitor is described as "any di or tri amine which may serve as a chelating agent."
U.S. Pat. No. 4,440,731 discloses a corrosion inhibitor composition for use in aqueous absorbent gas-liquid contacting processes for recovering carbon dioxide from industrial gas employing nickel and bismuth salts in combination with dihydroxyethylglycine.